Not Applicable.
Not Applicable.
1. Field of the Invention
The present invention relates generally to roller cone drill bits used for the drilling of boreholes and, more particularly, to roller cone drill bits where the axes of the cones are offset from the center of the bit and contains super-abrasive cutting elements.
2. Background of the Invention
A typical roller cone earth-boring bit includes one or more rotary cutters that perform their cutting function due to the rolling movement of the cutters acting against the formation. The cutters roll and slide upon the bottom of the borehole as the bit is rotated, the cutters thereby engaging and disintegrating the formation material in its path. The rotary cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones, roller cones, rotary cones and so forth. Drilling fluid which is pumped downwardly through the drill pipe and out of the bit carries the removed formations material upward and out of the borehole. In oil and gas drilling, the length of time it takes to drill to the desired depth and location effects the cost of drilling a borehole. The time required to drill the well is affected by the number of times the dill bit must be changed in order to reach the targeted formation. Each time the bit is changed, the entire string of drill pipe, which may be thousands of feet long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. This process, known as a xe2x80x9ctripxe2x80x9d of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and/or drill more footage and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed most often depends upon its rate of penetration (xe2x80x9cROPxe2x80x9d), as well as its durability or ability to maintain an acceptable ROP. Bit durability is, in part, measured by a bit""s ability to xe2x80x9chold gage,xe2x80x9d meaning its ability to maintain a full gage borehole diameter over the entire length of the borehole. Gage is required to be maintained to allow insertion of drilling apparatus as well as a decrease in ROP as well as to prevent premature gage wear of the next bit before it reaches the bottom of the hole. For example, when a new, unworn bit is inserted into an undergage borehole, the new bit will be required to ream the undergage hole as it progresses toward the bottom of the borehole. Thus, by the time it reaches the bottom, the bit may have experienced a substantial amount of wear that it would not have experienced had the prior bit been able to maintain full gage. This unnecessary wear will shorten the life of the newly-inserted bit, thus prematurely requiring the time consuming and expensive process of removing the drill string, replacing the worn bit, and reinstalling another new bit downhole.
To assist in maintaining the gage of a borehole, conventional rolling cone bits typically employ a heel row of hard metal inserts on the heel surface of the rolling cone cutters. The heel surface is a generally frustoconical surface and is configured and positioned so as to generally align with and ream the sidewall of the borehole as the bit rotates. The inserts in the heel surface contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall. The heel inserts function primarily to help maintain a constant gage and, secondarily, to prevent the erosion and abrasion of the heel surface of the rolling cone.
In addition to the heel row inserts, conventional bits typically include a gage row of cutter elements mounted adjacent to the heel surface but orientated and sized in such a manner so as to cut the comer of the borehole. In this orientation, the gage cutter elements generally are required to cut both the borehole bottom and sidewall. The lower surface of the gage row cutter elements engage the borehole bottom while the radially outermost surface scrapes the sidewall of the borehole. Excessive wear and/or breakage of the gage inserts can lead to an undergage borehole, decreased ROP, increased loading on the other cutter elements on the bit, and may accelerate wear of the cutter bearing due to intrusting and ultimately lead to bit failure. Conventional bits also include a number of additional rows of cutter elements that are located on the cones in rows disposed radially inward from the gage row. These cutter elements are sized and configured for cutting the bottom of the borehole and are typically described as inner row cutter elements.
Roller cone bits are known which have milled cutting teeth integrally formed with the roller cone as a cutting structure. Milled tooth bits, also known as steel tooth bits, have a hardmetal matrix welded to their teeth and are typically used where it is desired to drill at a faster rate through softer formations or at lower cost. However, the milled tooth bit tends to wear faster than the insert type bits causing it to drill a lesser total distance or footage.
Insert-type roller cone bits use hardened inserts which are press fit into undersized apertures in the rolling cones to serve as the cutting structure. A common insert type is tungsten carbide. Insert-type bits are more expensive and generally do not drill at as fast a rate in soft formations as milled tooth bits, however, insert bits have a longer drilling life and are, therefore, capable of drilling a greater total distance.
Bits are usually required to be specified in terms of an IADC nomenclature number which indicates the hardness and strength of the formation in which they are designed best to be employed. The bit""s IADC numeric nomenclature consists of a series of three numerals that are outlined within the xe2x80x9cBITSxe2x80x9d section of the current edition of the International Association of Drilling Contractors (IADC) Drilling Manual. The first numeral designates the bit""s series, of which the numerals 1-3) are reserved for Milled Tooth Bits in the soft, medium and hard formations and the numerals 4-8 are reserved for insert bits in the soft, medium, hard and extremely hard formations. The second numeral designates the bit""s type within the series. The third numeral relates to the mounting arrangement of the roller cones and is generally not directly related to formation hardness or strength and consequently represented by an xe2x80x9cxxe2x80x9d when IADC codes are referred to herein. A higher series numeral within the milled tooth and insert bit series indicates that the bit is capable of drilling in a harder formation than a bit with a lower series number. A higher type number indicates that the bit is capable of drilling in a harder formation than a bit of the same series with a lower type number. For example, a xe2x80x9c5-2-xxe2x80x9d IADC insert bit is capable of drilling in a harder formation than a xe2x80x9c4-2-xxe2x80x9d IADC insert bit. A xe2x80x9c5-3-xxe2x80x9d IADC insert bit is capable of drilling in harder formations than a xe2x80x9c5-2-xxe2x80x9d IADC insert bit. The IADC numeral classification system is subject to modification as approved by the International Association of Drilling Contractors to improve bit selection and usage.
xe2x80x9cOffsetxe2x80x9d is a term used when the axes of rotation of the rolling cone cutters are displaced from the longitudinal axis of the bit. When offset, also referred to as xe2x80x9cskew,xe2x80x9d is used in a roller cone bit, the cones try to rotate on the hole bottom about a xe2x80x9cfree rollingxe2x80x9d path, but they are not allowed to as they are attached to the bit body which forces them to rotate about the bit centerline or axis. Because the cone is forced to rotate about a non-free natural path, it imparts motions on the hole bottom that are referred to as in the art as xe2x80x9cskidding,xe2x80x9d xe2x80x9cgouging,xe2x80x9d xe2x80x9cscrapingxe2x80x9d and xe2x80x9csliding.xe2x80x9d These motions help to apply a shearing type cutting force to the hole bottom which can be a more efficient way of removing rock than compressive failure of rock cutting also known as a xe2x80x9ccrushing action.xe2x80x9d However, these shearing cutting forces will generally wear and break insert cutting elements much faster than compressive cutting forces, particularly on the gage row inserts because they cut the corner of the borehole which is typically the hardest area of the hole for inserts to work.
The use of offset axes in roller cone bits is not unknown, but has been limited in the amount of offset used. U.S. Pat. No. 4,657,093 issued to Schumacher described offset axis bits in which the offset amount is from {fraction (1/16)}xe2x80x3 to xe2x85x9xe2x80x3 per inch of bit diameter. Conventional tungsten carbide cutting inserts were used in the cones of these bits. Schumacher recognized that high offset cutters have not been thought practical. He noted that it was believed that increases in offset above a limit of {fraction (1/32)} inch per inch of bit diameter would gain very little in cutting efficiency, but would increase the amount of breakage of inserts in the bits. Schumacher taught that bits utilizing offsets of {fraction (1/32)}xe2x80x3 to {fraction (1/16)}xe2x80x3 per inch of bit diameter did not provide significant increases in ROP and drilling efficiency. Schumacher also taught that offset bits with tungsten carbine cutting inserts were primarily advantageous for soft to medium-soft formations. Schumacher also suggested that bits using his range of increased offset would suffer greater amounts of hard metal insert breakage. Thus, Schumacher""s bits were limited in the amount of total footage they could drill, as he provided no solution for the increased insert cutting element wear and/or breakage encountered. The benefits of increases in ROP were intended to offset the losses in potential total footage drilled. Increasing offsets generally leads to increased wear and/or breakage particularly on gage inserts that can create sharp edges and/or or thermal fatigue that leads to catastrophic insert breakage.
In an attempt to reduce the incidence of insert breakage, the cutting inserts could be made of tougher, and therefore less hard, insert material. However, such a design would sacrifice insert hardness, resulting in the bit becoming dull more quickly during use. As a result, the useful life for the offset bit would be shortened significantly.
Therefore, a need exists for a bit that is able to take advantage of increased ROP due to a high offset while at the same time better resisting insert breakage so that acceptable total footage can be drilled by the bit. Additionally, a need exists for such a bit that can be used in harder formations.
The present invention provides a xe2x80x9chighxe2x80x9d offset bit with reduced risk of insert breakage and wear by use of super-abrasive cutter elements so that improved cutting structures are provided among different bit types. High offset amounts are defined and described for the improved cutting structures offer an optimal mix of improved ROP, increased bit life and an enhanced ability to hold gage.
In the inventive bits, the axes of the roller cones are offset by a significant amount from the central longitudinal axis of the bit, thereby providing for significantly increased shearing and grinding action by the bit. The offsets used in particular bit types are larger, or xe2x80x9chigh,xe2x80x9d in relation to prior art offset bits of that type. xe2x80x9cHigh offsetsxe2x80x9d provide for increased sliding, gouging and scraping action upon the rock, thus resulting in greater drilling efficiency and ROP.
Further, the offset roller cones of the bits present gage cutting portions that have super-abrasive cutting surfaces, such as polycrystalline diamond (PCD) or cubic boron nitride coating (CBN). Gage inserts, secondary gage inserts, off-gage inserts and/or heel row inserts, provide the gage cutting portions, in most cases. The use of super-abrasive surfaces permits the amount of bit axis offset to be increased into high offset ranges without resulting in the bit becoming prematurely dull. At the same time, the Use of super-abrasive cutting surfaces in high-offset bits results in an unexpectedly low incidence of insert breakage, allowing for increased footage drilled and/or sustained increases in ROP. Super-abrasive inserts, such as polycrystalline diamond coated inserts have greater wear resistance as well as have better thermal fatigue resistance as compared to conventional tungsten carbide inserts, which ultimately gives them better resistance breakage.
In accordance with the general concepts and principles of the invention, a number of exemplary high offset bit configurations arc described. Bits are described that are suitable for use in formations of different hardnesses and in different drilling conditions and applications.
Specific embodiments are described herein wherein specific high offsets are defined and described for different bit diameters. For milled tooth bits and insert-type bits suitable for soft to medium-hard formations, minimum high offsets are provided which are at least xe2x85x9 inch when the bit diameter is less than 4 inches, at least {fraction (5/32)} inches when the bit diameter is 4 inches or greater and less than 5 inches , at least xc2xc inches when the bit diameter is 5 inches or greater and less than 7 inches, at least {fraction (11/32)} inches when the bit diameter is 7 inches or greater and less than 9 inches, at least {fraction (13/32)} inches when the bit diameter is 9 inches or greater and less than 12 inches, at least {fraction (7/16)} inches when the bit diameter is 12 inches or greater and less than 16 inches, and at least {fraction (17/32)} inches when the bit diameter is at least 16 inches. Particular ranges of high offsets are described as well. For soft to low strength formations, it is preferred that the offsets be at least {fraction (3/16)} inches when the bit diameter is less than 4 inches, at least xc2xc inches when the bit diameter is at least 4 inches and less than 5 inches, at least {fraction (5/16)} inches when the bit diameter is at least 5 inches and less than 7 inches, at least {fraction (7/16)} inches when the bit diameter is at least 7 inches and less than 9 inches, at least {fraction (9/16)} inches when the bit diameter is at least 9 inches and less than 12 inches, at least xc2xe inches when the bit diameter is at least 12 inches and less than 16 inches, and at least 1 inch when the bit diameter is at least 16 inches.
Recommended offsets are also provided for insert-type bits used for medium-hard to hard formations. For example, for use in extremely hard and high strength formations, the offset is greater than {fraction (1/16)} inches and less than {fraction (3/32)} inches when the bit diameter is less than 7 inches, at least {fraction (3/32)} inches and less than {fraction (5/32)} inches when the bit diameter is at least 7 inches and less than 12 inches, and at least {fraction (5/32)} inches and less than {fraction (7/32)} inches when the bit diameter is at least 12 inches.
In addition, high offsets and offset ranges are described for bits which have different IADC numeric nomenclatures and bit journal angles.
Thus, the present invention comprises a combination of features and advantages which 22 enable it to overcome various shortcomings of prior devices. The various characteristics described above, as sell as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings.